The present invention relates to methods for treating subterranean formations. More particularly, in certain embodiments, the present invention relates to methods of using in subterranean applications treatment fluids that comprise at least one entangled equilibrium polymer network.
In today's downhole technology, a large portion of the wells have been completed at depths of greater than 15,000 ft, and as a result, most previously designed treatment fluids and additives that were designed for more shallow wells may not perform adequately at temperatures and at pressures commonly associated with wells of greater depths. Wells at depths exceeding 15,000 ft often involve higher temperatures and pressures, necessitating the need for fluids and additives that will perform at these depths. In addition to the high temperatures and pressures, wells completed at these depths often produce fluids like carbon dioxide (CO2) or hydrogen sulfide (H2S).
Viscosified treatment fluids may be used in a variety of subterranean treatments. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid. Examples of common subterranean treatments include, but are not limited to, drilling operations, pre-pad treatments, fracturing operations, perforation operations, pre-flush treatments, after-flush treatments, sand control treatments (e.g., gravel packing), acidizing treatments (e.g., matrix acidizing or fracture acidizing), diverting treatments, cementing treatments, and well bore clean-out treatments. For example, in certain fracturing treatments generally a treatment fluid (e.g., a fracturing fluid or a “pad fluid”) is introduced into a well bore that penetrates a subterranean formation at a sufficient hydraulic pressure to create or enhance one or more pathways, or “fractures,” in the subterranean formation. These cracks generally increase the permeability of that portion of the formation. The fluid may comprise particulates, often referred to as “proppant particulates,” that are deposited in the resultant fractures. The proppant particulates are thought to help prevent the fractures from fully closing upon the release of the hydraulic pressure, forming conductive channels through which fluids may flow to a well bore penetrating the formation.
Treatment fluids are also utilized in sand control treatments, such as gravel packing. In “gravel-packing” treatments, a treatment fluid suspends particulates (commonly referred to as “gravel particulates”), and at least a portion of those particulates are then deposited in a desired area in a well bore, e.g., near unconsolidated or weakly consolidated formation zones, to form a “gravel pack,” which is a grouping of particulates that are packed sufficiently close together so as to prevent the passage of certain materials through the gravel pack. This “gravel pack” may, inter alia, enhance sand control in the subterranean formation and/or prevent the flow of particulates from an unconsolidated portion of the subterranean formation (e.g., a propped fracture) into a well bore. One common type of gravel-packing operation involves placing a sand control screen in the well bore and packing the annulus between the screen and the well bore with the gravel particulates of a specific size designed to prevent the passage of formation sand. The gravel particulates act, inter alia, to prevent the formation sand from occluding the screen or migrating with the produced hydrocarbons, and the screen acts, inter alia, to prevent the particulates from entering the well bore. The gravel particulates also may be coated with certain types of materials, including resins, tackifying agents, and the like. Once the gravel pack is substantially in place, the viscosity of the treatment fluid may be reduced to allow it to be recovered. In some situations, fracturing and gravel-packing treatments are combined into a single treatment (commonly referred to as “FRACPAC™” fracturing treatments). In such “FRACPAC™” fracturing treatments, the treatments are generally completed with a gravel pack screen assembly in place with the hydraulic fracturing treatment being pumped through the annular space between the casing and screen. In this situation, the hydraulic fracturing treatment ends in a screen-out condition, creating an annular gravel pack between the screen and casing. In other cases, the fracturing treatment may be performed prior to installing the screen and placing a gravel pack.
Maintaining sufficient viscosity in treatment fluids may be important for a number of reasons. Viscosity is desirable in drilling operations since treatment fluids with higher viscosity can, among other things, transport solids, such as drill cuttings, more readily. Maintaining sufficient viscosity is important in fracturing treatments for particulate transport, as well as to create or enhance fracture width. Particulate transport is also important in sand control treatments, such as gravel packing. Maintaining sufficient viscosity may be important to control and/or reduce leak-off into the formation, improve the ability to divert another fluid in the formation, and/or reduce pumping requirements by reducing friction in the well bore. At the same time, while maintaining sufficient viscosity of a treatment fluid often is desirable, it also may be desirable to maintain the viscosity of the treatment fluid in such a way that the viscosity may be reduced at a particular time, inter alia, for subsequent recovery of the fluid from the formation.
To provide the desired viscosity, polymeric gelling agents commonly are added to the treatment fluids. The term “gelling agent” is defined herein to include any substance that is capable of increasing the viscosity of a fluid, for example, by forming a gel. Examples of commonly used polymeric gelling agents include, but are not limited to cationic polymers, high molecular weight polyacrylamide polymers, polysaccharides, synthetic polymers, and the like. The use of pure polymeric gelling agents, however, may be problematic. For instance, these polymeric gelling agents may leave an undesirable gel residue in the subterranean formation after use, which can impact permeability. As a result, costly remedial operations may be required to clean up the fracture face and proppant pack. Foamed treatment fluids and emulsion-based treatment fluids have been employed to minimize residual damage, but increased expense and complexity often have resulted.
To combat perceived problems associated with polymeric gelling agents, some surfactants have been used as gelling agents. It is well understood that, when mixed with an aqueous fluid in a concentration above the critical micelle concentration, the molecules (or ions) of surfactants may associate to form micelles. Certain viscosifying micelles may impart increased viscosity to a fluid such that the fluid exhibits viscoelastic behavior (e.g., shear thinning properties) due, at least in part, to the association of the surfactant molecules contained therein.
However, the use of surfactants as gelling agents may be problematic in several respects. In certain applications, large quantities of viscoelastic surfactants may be required to impart the desired rheological properties to a fluid. Certain viscoelastic surfactants may be less soluble in certain fluids, which may impair the ability of those surfactants to form viscosifying micelles. Viscoelastic surfactant fluids also may be unstable at high temperatures and/or in high salt concentrations due to, among other things, the tendency of high salt concentrations to “screen out” electrostatic interactions between viscosifying micelles.